The present invention relates generally to a method and apparatus of hydrodynamically controlling well-bore fluids down in oil and/or gas wells to prevent uncontrolled well blowouts while maintaining any desired degree of fluid dynamics underbalanced, neutral balanced, or overbalanced conditions for drilling, completion, or work-over operations in such wells.
Well bore drilling is commonly performed by one of two techniques, namely overbalanced drilling and under balanced drilling. Overbalanced drilling refers to a well drilling process in which the drilling mud is maintained at a pressure greater than the formation pressure to inhibit the flow of fluids in the formation into the well bore. Under balanced drilling, in contrast, refers to a well drilling process in which the drilling mud is maintained at a pressure less than the formation pressure, thereby permitting formation fluids to flow into the well bore. Under balanced drilling techniques are gaining wider acceptance in the drilling industry because of the significantly lower likelihood of damage to the formation during drilling compared to overbalanced drilling techniques. When the drilling fluid has a greater pressure than the formation pressure, the formation can be damaged by penetration of drilling fluids into the formation or into formation fractures.
During the drilling, completion, and work-over operations in oil and gas wells, down-hole formation fluids entering the well bore may cause the well-bore fluids to be blown out of the well bore, which may result in an uncontrolled and hazardous well blowout or in very difficult operating conditions for the later work in the well bore. To prevent such uncontrolled blowouts, the operator/owner of the well typically circulates into position in the well bore a heavy enough fluid (i.e., drilling mud) to create a well-bore fluid pressure sufficient to exceed the current pressure of the formation fluid adjacent to the well bore, thereby preventing (i.e., killing) the flow of such formation fluid into the well bore. This process of circulating or injecting a fluid into the well bore of sufficient weight to prevent formation fluid from entering the well bore is commonly called xe2x80x9ckilling the wellxe2x80x9d, which results in well-bore fluid at the surface well head having no significant pressure.
This common practice of killing the well preparatory to tripping drill pipe or production equipment in or out of the well bore often results in serious damage to the formation around the well bore or adjacent to any fractures connected to the well bore. When the well is killed for any purpose, the wellbore fluid at higher pressure than the adjacent formation fluid will flow into the adjacent formation, resulting in reduction of the rock permeability to the production of formation fluids. In many formations, this reduction of permeability to formation fluids in the zones invaded by well-bore fluids may result in permanent or long-term damage to the well productivity. This damage is especially serious if a producing well, completed by hydraulic fracture stimulation, is killed because the killing well-bore fluid then may invade and damage the formation adjacent to the entire length and height of the hydraulic fracture.
As an alternative to killing the well with a heavy well-bore fluid, the drill pipe, production tubing or other equipment may be stripped in or out of the well under high well-head pressure through a snubbing unit. This procedure is expensive and complicated. Furthermore, if the well is shut-in under high pressure while stripping pipe or equipment in or out of the well through a snubbing unit, the liquids at the bottom of the well bore may be injected into the formation adjacent to the well bore and adjacent to the hydraulic fractures. In the zones invaded by these bottom-hole well-bore liquids while stripping through the snubbing unit, the rock permeability to the formation fluids may be severely damaged as described above.
In order to prevent damage to the producing reservoir formations, it is desirable not to kill the well by injection of well-bore fluids and not to shut-in the well with any liquids in the well bore as previously commonly done for the purpose of tripping drill pipe, production tubing or other equipment in or out of the well bore. To prevent reservoir damage from the invasion of well-bore liquids into the formation adjacent to the well bore or adjacent to the hydraulic fractures, it is desirable to maintain the down-hole well-bore fluid pressure at a level less than the then current pressure of the formation fluids in the adjacent reservoir rock. These fluids should flow only from the formation into the well bore or fracture and never from the well bore or fracture into the formation.
An objective of this invention is to provide a system for maintaining or regaining effective control of the well-bore fluids by circulating down hole a hydrodynamic control fluid through a dual path circulation system to prevent well-bore blow-outs under any drilling condition of underbalanced drilling, neutral balanced drilling, or overbalanced drilling, whether drilling ahead or while tripping the drill pipe out of the hole.
Another objective of this invention is to provide a system for maintaining a low or near-zero surface fluid pressure on the annulus fluid surrounding the drill pipe at the well head to permit the drill pipe to be rotated or moved up or down in the well bore while drilling ahead or tripping in or out of the hole without needing any high-pressure well-head rotating seal or pipe stripping seal and while maintaining any desired bottom-hole, well-bore pressure and any desired formation fluid flow dynamic condition in the lower portion of the well-bore.
An objective of this invention is to provide a system for under balanced drilling a well while substantially continuously maintaining the production (i.e., flow) of formation fluids into the well bore throughout all phases of the drilling operation, including tripping the drill string in and out of the well bore, while avoiding stripping the drill string in or out of the well head under significant or difficult high well-head pressures. During all phases of the drilling operation, the down-hole well-bore fluid pressure is not allowed to significantly exceed the formation fluid pressure adjacent to the well bore and, thereby, is not allowed to kill (i.e., stop) the continuous flow of formation fluids into the well bore and is not allowed to inject any non-formation fluids into the formations adjacent to the well bore.
Another objective of this invention is to provide a system for performing well work over, maintenance, completion, and recompletion operations in a producing oil and/or gas well, including the tripping of tubing and tools in and out of the well bore, without killing the well or stopping the continuous production of formation fluids into the well bore and without having to strip the tubing and tools in or out of the well head under significant or difficult well-head pressures. During all phases of these operations, the well-bore fluid pressure maintained at a level that does not significantly exceed the formation fluid pressure adjacent to the well bore and, thereby, is not allowed to kill (i.e., stop) the continuous flow of formation fluids into the well bore and is not allowed to inject any non-formation fluids into the formations adjacent to the well bore or adjacent to the hydraulic fractures extending from the well bore.
Another objective of this invention is to provide a system for performing any of the prior stated objectives without using a snubbing unit or other such surface pressure containment equipment to trip pipe and equipment in and out of the well bore.
Another objective of this invention is to provide a system for performing any of the prior stated objectives while being able to trip pipe and equipment in or out of the well bore without any produced formation fluids flowing out through the open well head through which such pipe and equipment is moving.
These objectives are realized by the methodology and system of the present invention. The method broadly includes the steps of: (a) introducing a hydrodynamic control fluid into a first flow pathway extending along an upper portion of the well bore which contains the drill shing; (b) commingling the downward flowing hydrodynamic control fluid with a well-bore fluid flowing upwardly from a lower portion of the well bore to form a commingled fluid; and (c) directing the flow of at least most of the commingled fluid along a second flow pathway that is different from the first flow pathway and extends along an upper portion of the well bore to maintain a fluid pressure in a selected portion of the well bore at or below a predetermined fluid pressure level near the bottom of the hole level. Commonly, the predetermined is less than the formation pressure. The fluid flow pathways preferably intersect to permit the hydrodynamic control fluid to commingle with the well bore fluid and the commingled fluid to enter the second flow pathway. The various flow pathways are defined by the positioning of one or more casings in the well bore.
By way of illustration, in one casing configuration the produced formation fluids, commingled with other well-bore fluids, flowing up the well bore from below are diverted into a controlled flow discharge path (or second flow pathway) located in an outer annulus defined by an inner casing and an outer casing. The hydrodynamic control fluid flows downwardly inside of the inner casing (the first flow pathway). The inner casing is hereinafter referred to as the inner hydrodynamic control casing. The hydrodynamic downward flow of a liquid preferably has a downward velocity greater than the upward migration velocity of gas and/or oil bubbles and/or gas and/or oil slugs attempting to rise through the hydrodynamic control fluid (which is preferably a liquid or gelled liquid) by buoyancy. This hydrodynamic control fluid flows downwardly inside the inner hydrodynamic control casing and then flows around the bottom of the inner casing and/or through perforations in the inner hydrodynamic control casing and into the outer annulus. In the outer annulus the hydrodynamic control fluid commingles with the mixture of upwardly flowing well-bore fluids from below as they are diverted from a third annulus located below the fluid interconnection between the annulus inside the inner casing and the annulus between the inner and outer castings.
The commingled fluid s flow upwardly in the outer annulus to the casing head and then out through discharge ports, valved manifolds, and flow lines to a discharge and burn pit. The commingled fluids flow into the discharge/burn pit at atmospheric pressure. The pressure gradient along the discharge flow path up the outer annulus is dependent upon the average density of the coming led fluids and its dynamic friction loss along the outer annulus.
However, if the commingled discharge fluids contain significant amounts of expanding formation gas, the pressure gradient can be very low. In that event, with the discharge to the burn pit being at atmospheric pressure and the average pressure gradient of the commingled discharge fluids in the outer annulus being very low, the down-hole pressure at the bottom of and/or perforations in the inner casing will be substantially less than the hydrostatic head of water from the surface to the depth of the bottom and/or perforations in the inner casing. Consequently, if water drilling mud or other liquid is pumped down the inner casing to create the hydrodynamic down flow needed to divert the up-flowing formation/well-bore fluids from below out into the outer annulus, then the dynamic water drilling water or other liquid level in the inner casing may be several hundred feet below the well head at the ground surface. In this case, the pipe and equipment can be tripped in or out of th e well bore dry with n o formation fluid (i.e., gas or oil) appearing inside the open inner casing at the surface.
However, large volumes of formation fluids (i.e. including gas and/or oil) may nonetheless be diverted hydrodynamically at the bottom of or perforations in the inner casing and, thereby, be caused to flow up the annulus between the two casings and be discharged at controlled low pressures into the burn pit (or separator tanks). This pressure controlled discharge of produced formation fluids up through the annulus between the inner and outer casings and out through a valved manifold to a burn pit (or separator tanks) provides the means to maintain controlled, low, bottom-hole pressure to assure continuous production of formation fluids into the well bore and to prevent the injection of any non-formation fluid from the well bore into the formation (or fractures) during any tripping of pipe or equipment or any work or operations being done in the well bore.
An optional piece of equipment that may be added at the bottom of the inner casing to inhibit the entry of well-bore fluids into the inner casing and to substantially reduce the volume rate of injecting the hydrodynamic control fluid down the inner casing is a leaky hydrodynamic partial barrier. This piece of equipment, also called a hydrodynamic barrier, may be (a) a rubber seal similar to a drilling rotating head, (b) a semi-circular, cross-sectional donut ring of flexible, deformable rubber, whose inside diameter can be elastically stretched to loosely fit over the diameter each of the tools or pipe which need to pass through this barrier, (c) an inverse, flexibly deformable, belly-spring centralizer bag squeezing inward from the inner casing wall, (d) a surface controlled, hydraulically actuated, down-hole, shut-off valve or partial shut-off restriction and/or such shut-off valve with a limited volume, fluid by-pass opening, or (e) many alternative designs as may be created by oil/gas tool design engineers who are skilled in the art of designing, manufacture, and operation of similar down hole, well-bore tools.
This hydrodynamic barrier is designed not to make a pressure seal against the centralized pipe or tools but rather to provide a reduced cross-sectional area flow path for the downward flowing hydrodynamic fluids. This reduced cross-sectional area flow path creates a proportionally increased flow velocity of the hydrodynamic fluid flowing past this barrier. Consequently, the velocity of the downward flow past this reduced area hydrodynamic barrier can be sufficient to exceed the velocity of gas bubbles or slugs of gas trying to migrate upward by buoyancy in the hydrodynamic control fluid even when the volumetric rate of injecting the hydrodynamic control fluid into the inner casing is very low. The horizontal cross-sectional area of the leakage path adjacent to the hydrodynamic barrier preferably ranges from about 2% to 20% of the horizontal cross-sectional area of the inner annulus. Also, the hydrodynamic control fluid above this hydrodynamic barrier may be gelled to increase its viscosity, and decrease the buoyancy upward velocity of gas bubbles or gas slugs in the hydrodynamic control fluid and thereby further decrease the volumetric flow rate of the control fluid needed to achieve the hydrodynamic diversion control objective.
The pressure difference across this hydrodynamic barrier should be very small. In many well-bore applications, this optional hydrodynamic barrier is not needed and will not be used. The hydrodynamic control fluid viscosity, gel strength, density, and height will provide adequate means to control the diversion of the commingled fluid out into the outer annulus. The pressure at the bottom of the column of hydrodynamic control fluid inside the inner casing may be only a few psi greater than the fluid pressure below the barrier the pressure of the column of produced formation fluids commingled with the other well-bore fluids flowing up the annulus between the inner and outer casings and vented to the burn pit. If the fluid column diverted to flow up the outer annulus contains a significant volume of expanding gas that decreases the density of the fluid column and if the fluid column is vented to the atmosphere in the burn pit, then the low fluid pressure at the bottom of this outer annulus where these fluids are commingled will be balanced by the pressure of the column of the properly designed hydrodynamic control dynamic fluid, with a height shorter than the distance to the surface well head. Therefore, the hydrodynamic control fluid can be pumped into the inner casing at atmospheric pressure, and it will fall down the inner casing to the fluid level and thereby balance the pressure of the column of low-density, commingled produced fluids (including expanding gas) flowing up the outer annulus and out to the bum pit. Consequently, the pipe and tools needed for drilling, completing, or work over can be tripped through the well head and into or out of the well bore with substantially zero fluid pressure at the surface and no produced fluids coming to the surface inside the inner casing to hinder the crew working on the derrick floor. The purpose of the increased viscosity of the gelled water hydrodynamic control fluid, is to reduce the volume rate of injecting the hydrodynamic control fluid into the inner casing needed to prevent the produced fluids (i.e., oil and/or gas) from migrating by buoyancy up through the hydrodynamic control fluid.
Accordingly, the system and method of the present invention acts as and is therefore hereinafter referred to as the down-hole xe2x80x9chydrodynamic blowout-preventerxe2x80x9d, or xe2x80x9cH-BOPxe2x80x9d.